Smart seal methods and systems

ABSTRACT

An apparatus for monitoring the condition of a seal, such as a seal in a blowout preventer or in another oilfield device, is provided. In one embodiment, the apparatus includes a blowout preventer including a seal and a blowout preventer seal-monitoring system that includes a sensor positioned within a body of the seal and a data analyzer. The data analyzer has a processor and is configured to monitor a condition of the seal through analysis of data received by the data analyzer from the sensor positioned within the body of the seal. Additional systems, devices, and methods are also disclosed.

BACKGROUND

This section is intended to introduce the reader to various aspects ofart that may be related to various aspects of the presently describedembodiments. This discussion is believed to be helpful in providing thereader with background information to facilitate a better understandingof the various aspects of the present embodiments. Accordingly, itshould be understood that these statements are to be read in this light,and not as admissions of prior art.

In order to meet consumer and industrial demand for natural resources,companies often invest significant amounts of time and money in findingand extracting oil, natural gas, and other subterranean resources fromthe earth. Particularly, once a desired subterranean resource such asoil or natural gas is discovered, drilling and production systems areoften employed to access and extract the resource. These systems may belocated onshore or offshore depending on the location of a desiredresource.

Further, such systems generally include a wellhead assembly mounted on awell through which the resource is accessed or extracted. These wellheadassemblies may include a wide variety of components, such as casings,hangers, blowout preventers, fluid conduits, pumps, and the like, thatfacilitate drilling or production operations. Wellhead assembliestypically include many seals for containing fluid pressure. Examples ofsuch seals include ram top seals, ram packers, annular packers, gaskets,and O-rings. These seals wear during use and may be replaced afterfailure or on a regularly scheduled basis.

SUMMARY

Certain aspects of some embodiments disclosed herein are set forthbelow. It should be understood that these aspects are presented merelyto provide the reader with a brief summary of certain forms theinvention might take and that these aspects are not intended to limitthe scope of the invention. Indeed, the invention may encompass avariety of aspects that may not be set forth below.

Embodiments of the present disclosure generally relate to sensors formeasuring the condition of seals, such as those found in wellheadassemblies or other oilfield components. For instance, variousembodiments described below include sensors embedded in seals foracquiring data that can be used to determine and monitor the conditionof the seals. The acquired data may include measurements of physicaloperating conditions, such as measurements of temperature, stress, orstrain experienced by the seal. In some embodiments, sensors areprovided as wires embedded in elastomeric seals and the acquired dataincludes electrical measurements from the wires, which can be analyzedto determine seal condition. While seal data acquired with the sensorscan be used for condition-based monitoring, the data could be used forother purposes, such as for predictive maintenance, controllingoperation of a wellhead assembly component (e.g., a blowout preventer),or tracking objects (e.g., drill string tool joints) passing through awellhead assembly.

Various refinements of the features noted above may exist in relation tovarious aspects of the present embodiments. Further features may also beincorporated in these various aspects as well. These refinements andadditional features may exist individually or in any combination. Forinstance, various features discussed below in relation to one or more ofthe illustrated embodiments may be incorporated into any of theabove-described aspects of the present disclosure alone or in anycombination. Again, the brief summary presented above is intended onlyto familiarize the reader with certain aspects and contexts of someembodiments without limitation to the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of certain embodimentswill become better understood when the following detailed description isread with reference to the accompanying drawings in which likecharacters represent like parts throughout the drawings, wherein:

FIG. 1 generally depicts a well apparatus in the form of an offshoredrilling system with a drilling rig coupled by a riser to a wellheadassembly in accordance with one embodiment of the present disclosure;

FIG. 2 is a block diagram of a seal-monitoring system including a sealof an oilfield component, the seal having a sensor for measuringoperating data, and a data analyzer for processing the operating datacollected by the sensor in accordance with one embodiment;

FIG. 3 depicts a blowout preventer stack assembly having variouscomponents with seals having sensors for measuring operating data thatmay be used for condition-based monitoring in accordance with oneembodiment;

FIG. 4 is a block diagram of a data acquisition system for obtainingseal data in accordance with one embodiment;

FIG. 5 is a block diagram of a programmable data analyzer that can beused for condition-based monitoring in accordance with one embodiment;

FIG. 6 depicts a blowout preventer having various seals in accordancewith one embodiment;

FIG. 7 depicts two rams of the blowout preventer of FIG. 6 in additionaldetail in accordance with one embodiment;

FIGS. 8 and 9 depict a ram packer with sensors for collecting operatingdata for the packer in accordance with one embodiment;

FIGS. 10 and 11 depict another ram seal with sensors for collectingoperating data for the seal in accordance with one embodiment;

FIG. 12 depicts an annular blowout preventer having various sealingcomponents with embedded sensors in accordance with one embodiment;

FIGS. 13 and 14 generally depict a packer of an annular preventer closedabout different portions of a drill string in accordance with oneembodiment;

FIG. 15 depicts a blowout preventer with a data receiver embedded in abody of the blowout preventer to facilitate wireless communication witha sensor-enabled seal in accordance with one embodiment;

FIG. 16 depicts a ram packer having an embedded wear sensor inaccordance with one embodiment; and

FIGS. 17-19 depict another seal having an embedded wear sensor inaccordance with one embodiment.

DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS

Specific embodiments of the present disclosure are described below. Inan effort to provide a concise description of these embodiments, allfeatures of an actual implementation may not be described in thespecification. It should be appreciated that in the development of anysuch actual implementation, as in any engineering or design project,numerous implementation-specific decisions must be made to achieve thedevelopers' specific goals, such as compliance with system-related andbusiness-related constraints, which may vary from one implementation toanother. Moreover, it should be appreciated that such a developmenteffort might be complex and time consuming, but would nevertheless be aroutine undertaking of design, fabrication, and manufacture for those ofordinary skill having the benefit of this disclosure.

When introducing elements of various embodiments, the articles “a,”“an,” “the,” and “said” are intended to mean that there are one or moreof the elements. The terms “comprising,” “including,” and “having” areintended to be inclusive and mean that there may be additional elementsother than the listed elements. Moreover, any use of “top,” “bottom,”“above,” “below,” other directional terms, and variations of these termsis made for convenience, but does not require any particular orientationof the components.

Turning now to the present figures, a well apparatus 10 is illustratedin FIG. 1 in accordance with one embodiment. The apparatus 10 (e.g., adrilling system or a production system) facilitates access to orextraction of a resource, such as oil or natural gas, from a reservoirthrough a well 12. The apparatus 10 is generally depicted in FIG. 1 asan offshore drilling apparatus including a drilling rig 14 coupled witha riser 16 to a wellhead assembly 18 installed at the well 12. Althoughshown here as an offshore system, the well apparatus 10 could instead bean onshore system in other embodiments.

As will be appreciated, the drilling rig 14 can include surfaceequipment positioned over the water, such as pumps, power supplies,cable and hose reels, control units, a diverter, a gimbal, a spider, andthe like. Similarly, the riser 16 may also include a variety ofcomponents, such as riser joints, flex joints, a telescoping joint, fillvalves, and control units, to name but a few. The wellhead assembly 18includes equipment, such as blowout preventers, coupled to a wellhead 20to enable the control of fluid from the well 12. Any suitable blowoutpreventers could be coupled to the wellhead 20, such as ram-typepreventers and annular preventers. The wellhead 20 can also includevarious components, such as casing heads, tubing heads, spools, andhangers.

The drilling rig 14, the riser 16, and the wellhead assembly 18 includevarious oilfield components having seals for containing fluid pressure.Seals of blowout preventers and other oilfield components are prone tofailure owing to age, degradation of material, abuse, excessivepressure, excessive stresses, extremes of temperature, wear, and myriadother influences. In some instances, seals are replaced on a scheduledbasis (e.g., after a pre-defined time, cycle count, or event) regardlessof condition. In at least the case of blowout preventers, suchreplacement frequently requires considerable time and effort given thenature of the blowout preventer equipment and the steps necessary toaccess the seals for replacement. The blowout preventer is necessarilyout of commission while such work is performed. Seals are also replacedwhen they are known to have failed. This will often be following apotentially lengthy investigation to diagnose the source of a leak.

The physical properties of a seal can vary with operating conditions,such as environmental conditions (e.g., temperature) and forces (e.g.,stress and strain) experienced by the seal. Traditionally, the sealsused throughout a blowout preventer and in other oilfield components aresimply shaped pieces of material. These traditional seals are notintelligent, do not provide feedback, and are not capable of reportingtheir health or the operating conditions they have been exposed to.

In accordance with at least certain embodiments of the presentdisclosure, however, oilfield components are provided with “smart” sealshaving embedded sensors that enable the acquisition of data relevant tothe seals and their operation from the seals themselves. The acquireddata can be used for condition-based monitoring and predictivemaintenance, among other things. A simple example of an oilfieldcomponent 24 having a seal 26 with an embedded sensor 28 is generallydepicted in FIG. 2. Various examples of oilfield components with suchsmart seals having sensors are described in greater detail below, but itwill be appreciated that oilfield components 24 and their seals 26 maytake many different forms in addition to those described below. In atleast some embodiments, the seal 26 is an elastomer seal having theembedded sensor 28. The seal 26 can include a ram packer, a ram topseal, an annular packer, an O-ring, a gasket, a pressure seal, a wiperseal, or a shaft seal, to name just some examples. In some embodiments,the seals 26 include local power generation and communications, asfurther described below.

The types of data acquired with sensors in the seals may vary dependingon the location and importance of the seals. In some embodiments, thesmart seals measure actual forces or environmental conditionsexperienced by the seals. For example, sensors 28 can be used to measuretemperature or pressure experienced by the seals. The sensors 28 areprovided as fiber-optic sensors in certain embodiments. The influence oftemperature and pressure on the seal will, in turn, influence theproperties of the embedded optical fibers of the sensors and, withsuitable experimental calibration, will give rise to an indication ofphysical conditions experienced by the seal. In the case of blowoutpreventers, the physical conditions experienced by the seal can bedetermined from the sensor data during its operating cycle (includingstationary phases when the blowout preventer is fully open or fullyclosed). Sensors 28 may also or instead be provided as strain gaugesembedded in the bodies of smart seals 26 to measure stress and strain(which may include shear) experienced by the seals. The strain gaugescould be single-axis or multi-axis strain gauges, and in one embodimentthe sensors 28 include multiple single-axis strain gauges embeddedwithin a smart seal in a multi-axis configuration.

By recording such data and comparing with baseline data for similarseals including, for example, the manufacturer's specifications andrecommended operating conditions for the type of seal, or empirical datafrom a deployed population of such seals, the user can be alerted toinstances where the forces exerted on a seal have been measured to bebeyond those recommended by the baseline data. This information may beuseful in the context of condition-based monitoring and predictivemaintenance.

Another measurement that can be considered in at least certainembodiments is fluid ingress. If the ingress of fluid is detected withinthe seal itself (via the embedded sensor) this may suggest a leak ordegradation of the seal material. In either case, the operator can bealerted to the need for further investigation and potential remedialaction. In further embodiments, sensors embedded within smart seals candetect the presence of specific chemicals within the seal.

In situations where smart seals are used with dynamic components (e.g.,blowout preventer rams) such that the seal travels along anothercomponent (or another component travels past the seal), and depending onthe other data available (e.g., speed and time of movement), the stressexperienced by the seal can be used to determine what the degree offriction is in the bore. This might indicate a build-up of unwantedmaterial, the deterioration of the surface of the bore owing to say,galling, or some other issue that merits investigation. High frictionwill, among other things, increase the wear on the seal and couldrequire it to be replaced sooner than expected. In one embodiment,friction on a seal due to relative motion of the seal and anothercomponent is determined from stress measured with a sensor embedded inthe seal. The determined amount of friction can be compared with afriction threshold (e.g., an expected friction level or maximum desiredfriction level) and an operator can be alerted if the determined amountof friction exceeds the threshold amount. Trends in data acquired withthe seal sensors can also be monitored over time to facilitatecondition-based-monitoring.

Depending on the nature of the sensor and the one or more measurementsto be made, it may be desirable to embed multiple sensors in a singleseal (e.g., to provide distributed sensing coverage throughout theseal). For example, small, area-focused sensors (such as strain gauges)could be embedded at multiple locations within a seal, whereas others(such as fiber-optic sensors) may span the length of a seal.

From the above, it will be appreciated that monitoring either or boththe environmental conditions and the actual forces experienced by sealcomponents with embedded sensors enables a more holistic approach toseal condition monitoring and replacement. A seal-monitoring system fora blowout preventer (or for another apparatus) can include one or moresmart seals 26 and a data analyzer 30 for processing data acquired withthe smart seals 26. In some embodiments, the data analyzer 30 comparesdata acquired with the smart seals (e.g., stresses and temperaturesexperienced by the seals) to appropriate baseline data and usespredictive algorithms to calculate an expected performancecharacteristic for the seals. The expected performance characteristiccould be an expected longevity of a seal based on the experiencedconditions. It will be appreciated that the expected longevity could beexpressed in different ways, such as an estimated remaining service lifeor a total expected length of service.

In some cases, this analysis may suggest replacement of seals earlierthan either cycle count or elapsed time would suggest. Such a suggestionmay be in response to harsh operating conditions or misuse, for example,and may prevent unplanned downtime (perhaps pulling the whole blowoutpreventer, thus incurring millions of dollars of lost revenue) orpossible failure of the equipment to operate as designed when required(e.g., to prevent a blow-out). In other cases, analysis of the dataacquired with sensors of the smart seals may indicate that the sealscould be replaced much later than ether cycle count or elapsed timewould suggest. This delayed maintenance may save equipment operatorssignificant amounts of time and allow these operators to delayexpenditure associated with the maintenance.

The data analyzer 30 can receive and analyze smart seal data frommultiple components. By way of example, the data analyzer 30 isgenerally depicted in FIG. 3 as being coupled (e.g., via wired orwireless connections) to receive data from seals of various componentsof a subsea blowout preventer stack assembly 34. The stack assembly 34includes a lower blowout preventer stack 36 that can be coupled abovethe wellhead 20. The lower blowout preventer stack 36 includes ram-typepreventers (e.g., represented as shear rams 38 and pipe rams 40) and anannular preventer 42. The blowout preventer stack assembly 34 is furthershown in FIG. 3 as including a lower marine riser package (LMRP) 46having an annular preventer 48.

The data analyzer 30 can process the data acquired by smart seals of thestack assembly 34 (e.g., of the shear rams 38, the pipe rams 40, and theannular preventers 42 and 48), such as to determine seal condition. Thedata analyzer 30 could be positioned near one or more components havinga seal with an embedded sensor (e.g., as part of the stack assembly 34),or could be provided remote from any such smart seals. In one subseaembodiment, the data analyzer 30 is provided at the surface on thedrilling rig 14. The data acquired by the smart seals could also orinstead be transmitted to other locations for processing, such as to anonshore processing site remote from the drilling rig 14. Further, thedata analyzer 30 could be provided as part of a system for monitoringthe condition and operation of other components (e.g., a system formonitoring operation of a blowout preventer stack).

It will be appreciated that the lower blowout preventer stack 36 and theLMRP 46 can include other components in addition to or in place of thosedepicted in FIG. 3. The LMRP 46, for example, can include control podsfor controlling operation of the preventers of the lower blowoutpreventer stack 36 and the LMRP 46. Additionally, in some embodiments(e.g., onshore embodiments) the LMRP 46 is omitted from the blowoutpreventer stack assembly 34.

A bore through the blowout preventer stack assembly 34 allows objects,such as a drill string, to pass into the well 12. The drill string andother objects may routinely pass through the bore of the blowoutpreventer stack assembly 34 during normal operations. Examples of otherobjects that may pass through the stack assembly 34 include reamers,downhole assemblies, running tools, and other tools. As discussed ingreater detail below, a component of the stack assembly 34 (e.g., theannular preventer 42) can have a smart seal with an embedded sensor thatenables the detection of objects (e.g., drill string tool joints)passing through the component. This detection (e.g., by the dataanalyzer 30 through analysis of data from the embedded sensor) can beused for tracking the objects and controlling operation of thecomponent.

Various components can be used to facilitate data acquisition with thesmart seals 26. For instance, in FIG. 4, a data acquisition system 60 isgenerally depicted as including a power supply 64, one or more sensors66, data storage 68 (e.g., a memory device), a processor 70, and one ormore communications devices 72. The data acquisition system 60 couldinclude other components in addition to, or in place of those depictedin FIG. 4. The various components can be operatively coupled to oneanother in any suitable manner to facilitate electrical communication(e.g., of power, measurement data, communications, and control signals),such as with one or more shared buses 74.

Components of the data acquisition system 60 can be embedded in the bodyof a seal to facilitate measurement of various operational data, such asmeasurements of environmental conditions or forces experienced by theseal. While a smart seal 26 may include a sensor 66 as the embeddedsensor 28, the smart seal 26 may also include other components embeddedin the body of the seal 26. For instance, any or all of a power supply64, data storage 68, processor 70 (or other control circuitry), and acommunications device 72 could also be embedded within the body of theseal 26. With careful choice of materials and the use of very smallcomponents it may be possible to manufacture seals that display the samemechanical properties as those manufactured without embedded devices. Asone example of this, by using a material for a sensor substrate that ischemically similar to the host material, the bonding between theembedded component and the host material is maximized.

Depending on where the seal is fitted within a blowout preventer (orwithin some other component), there are multiple options for providingpower to the sensors embedded in it. Three examples of these options aredepicted in FIG. 4 as an inductive coupling 76, a piezoelectricgenerator 78, and a wired connection 80. It will be appreciated that thepower supply 64 could be provided in any one of these forms, in adifferent form (e.g., a battery), or in any combination of suitableforms. In some instances, a seal 26 has an exposed edge that allowsdirect connection of wires to trailing leads from the sensor. In otherinstances, such as with seals internal to a component, local powergeneration within the seal 26 may be desirable. The seal 26 in oneembodiment uses an inductive coupling 76 having a close-proximity butnon-contact connection between the primary and secondary elements (e.g.,coils) of an inductive coupler. The secondary element of the inductivecoupler can be embedded within the seal body, while the primary elementis provided in close proximity outside the seal. In other embodiments, apiezoelectric generator 78 embedded in the seal 26 may be used toprovide power to the other electronic components in the seal. In oneexample of the generator 78, pressure from a local source (e.g., controlfluid or wellbore fluid) is harnessed to deform a piezoelectric element,thus generating electrical energy. This energy can be stored in acapacitor to act as a battery for the embedded electrical components(e.g., the sensor 66).

There are also various options for communicating with sensors embeddedin seals 26. By way of example, a seal 26 could include one or more ofan antenna 82, a radio-frequency identification (RFID) tag 84, or awired connection 86 to enable communication between components embeddedwithin the seal and an external system (e.g., an external data analyzer30). The particular device or devices used for communication may dependon the accessibility of the seal 26 in the component 24. If the seal 26has an exposed edge, a wired connection 86 may be used (e.g., withdirect connection of wires to trailing leads from the sensor). If theseal is internal to the component 24, then any suitable wirelessapproach may be used. For example, an approach based on RFID (e.g.,using an RFID tag 84) could be used to communicate with the antenna 82embedded in the seal 26 along with the one or more sensors 66 beingread.

The retrieval of data acquired with embedded sensors 66 might beperformed in real-time, in pseudo real-time, or on a batch basis. In oneembodiment, the sensor remains in communication with an external datareceiver (e.g., of the data analyzer 30) and the real-time approach willreport each reading by the sensor as it is made. In another embodiment,the pseudo real-time approach will report each reading shortly after itis made. This allows the sensor to be out of communication with thereceiver at the time the reading is made, and to reestablishcommunication and transmit the sensor reading shortly thereafter. Asdiscussed more particularly below with reference to FIG. 15, one exampleof this would be where the sensor reading is made at the end of thetravel of a ram, where the elements of the communications link (e.g.,the antenna 82 and the external receiver) are too far apart. When theram travels back to its default position, however, the elements of thecommunications link are close enough to function. In a furtherembodiment, the batch-basis approach will provide for the batch downloadof data from a storage device (e.g., the data storage 68) associatedwith one or more embedded sensors of a smart seal. This approach couldbe adopted where sensors are in particularly hard-to-reach locations orwhere the nature of the monitoring is such that it is acceptable tosimply download the data on an irregular basis. In some instances, asmart seal of a component may alternate between communicating inreal-time, in pseudo real-time, or on a batch basis.

The nature of the seals in a blowout preventer assembly is such that itmay not be necessary to retrieve the information in real-time. As longas the data are gathered and transmitted to the operator on a regularbasis (e.g., daily), then the trends and likely effects of extremeconditions can be brought to the operator's attention. It will beappreciated, however, that the information could be retrieved inreal-time in some embodiments. Depending on the location and nature of asmart seal of a subsea blowout preventer stack, it might be useful (oreven necessary, in some instances) to download and process the data whenthe blowout preventer stack is returned to the drilling rig forservicing. In this situation, the data on seal performance will allowmaintenance personnel to make informed decisions as to which seals toreplace, inspect, or ignore.

In some embodiments, it might not be possible to provide all sensorswith sufficient on-going energy to maintain the operation of a clock. Insuch cases, the data may be written to the local data storage device 68in chronological order. While it may not then be possible to plot atrend against a specific time, trends will still be visible, such as adetected increase in fluid ingress or ongoing exposure to high shearstrains that indicate likely premature failure of the seal.

Recording of data measured by embedded sensors of smart seals may beomitted in those cases where the data are recorded in real-time orpseudo real-time, since these cases imply an adequate communicationslink to retrieve the data. In some such instances, the data are timestamped at the point of reception by the communications device (areceiver of the data analysis system 30) and will allow correlationbetween the seal (sensor) data and other events related to blowoutpreventer operations (e.g., commands to close a ram). Being able tosuperimpose such data in a flexible manner on the user's interface mayallow for powerful insights into how the equipment behaves under a rangeof operating conditions.

It is noted that the data analyzer 30 for implementing variousfunctionality described herein can be provided in any suitable form. Inat least some embodiments, such a data analyzer 30 is provided in theform of a processor-based system, an example of which is illustrated inFIG. 5 and generally denoted by reference numeral 90. In this depictedembodiment, the system 90 includes a processor 92 connected by a bus 94to a memory device 96. It will be appreciated that the system 90 couldalso include multiple processors or memory devices, and that such memorydevices can include volatile memory (e.g., random-access memory) ornon-volatile memory (e.g., flash memory and a read-only memory). The oneor more memory devices 96 are encoded with application instructions 98,such as software executable by the processor 92 to analyze data fromsmart seals for condition-based monitoring, predictive maintenance, sealfriction determination, blowout preventer control, or object tracking,or to provide other functionality described herein. Data 100 (e.g., sealmanufacturer's specifications and recommended operating conditions,other baseline data) may also be stored in memory devices 96. In oneembodiment, the application instructions 98 are stored in a read-onlymemory and the data 100 are stored in a writeable non-volatile memory(e.g., a flash memory).

The system 90 also includes an interface 102 that enables communicationbetween the processor 92 and various input or output devices 104. Theinterface 102 can include any suitable device that enables suchcommunication, such as a modem or a serial port. In at least someembodiments, the interface 102 includes a wireless data receiver forreceiving data from smart seals. The input and output devices 104 caninclude any number of suitable devices. For example, in one embodimentthe devices 104 include smart seals 26, and data transmitted from thesmart seals 26 can be analyzed with the processor 92 for condition-basedmonitoring. The devices 104 could also include a keyboard to allowuser-input to the system 90 and a display or printer to outputinformation from the system 90 to a user.

Additional embodiments with smart seals 26 having embedded sensors aredepicted in FIGS. 6-19 and described below. It will be appreciated,however, that smart seals with embedded sensors can be used in a varietyof other components and arrangements. By way of example, a blowoutpreventer 110 with smart seals is depicted in FIG. 6. The blowoutpreventer 110 includes a body 112, a bore 114 that enables passage offluid or tubular members through the blowout preventer 110, and bonnetassemblies 116 mounted to the body 112. Each ram 118 inside the blowoutpreventer 110 is moved into or out of the bore 114 by an associatedpiston 120 and connecting rod 122 of a bonnet assembly 116. In thepresently illustrated embodiment, the connecting rod 122 includes abutton received in the ram 118 to allow the connecting rod 122 to pushor pull the ram 118 within the blowout preventer 110.

The rams 118 are depicted as pipe rams in FIG. 6, and are shown ingreater detail in FIG. 7. Each ram 118 includes a body or ram block 126,a ram seal 128 (shown as a top seal in FIG. 7), and a ram packer 130.The ram seal 128 and the ram packer 130 include elastomeric materialsthat facilitate sealing by the ram 118 within the blowout preventer 110.The ram packer 130 includes alignment pins 132 that may be received incorresponding slots of the ram block 126 when the ram packer 130 isinstalled. The ram packers 130 include an elastomeric body 134 andrecesses 138 that allow a pair of opposing rams 118 to close about andseal against a tubular member (e.g., drill pipe). The recesses 138 maybe sized according to the diameter of the pipe about which the packers130 are intended to seal. Additionally, in other embodiments, the rams118 could be provided as variable-bore pipe rams used to seal aroundpipes within a range of diameters. Each ram 118 also includes a slot 140for receiving a portion (e.g., a button) of a connecting rod 122, asdiscussed above.

The ram seals 128 and the ram packers 130 can be provided as smart sealswith any desired number, type, and arrangement of embedded sensors. InFIGS. 8 and 9, a ram packer 130 is shown as having fiber-optic sensors148 embedded in its elastomeric body 134. The fiber-optic sensors 148are provided near the contoured front face of the packer 130 designed toseal around an object in the bore of the blowout preventer 110 and toclose against an opposing ram packer 130. The fiber-optic sensors 148may run parallel to the front face of the packer 130 and follow thecontour of the front face (including bending near the middle of thesensors to accommodate the recess 138). The depicted ram packer 130 alsoincludes a power supply 150, electronics 152, and strain gauges 154embedded in the elastomeric body 134. The power supply 150 can beprovided in any suitable form (e.g., a piezoelectric generator 78), andthe electronics 152 may include various circuitry that facilitatesoperation of the smart seal (e.g., data storage 68, processor 70, andcommunications circuitry). An antenna 156 (e.g., an RFID antenna) canalso be embedded in the elastomeric body 134 for communications. Twoorientations of the antenna 156 are shown in FIG. 9. While the packer130 could include two separate antennas 156 (e.g., for redundancy and toimprove throughput), it will be appreciated that a single antenna 156could instead be used (in either orientation shown in FIG. 9, or in someother orientation).

An example of a ram seal 128 with smart seal functionality is generallyillustrated in FIGS. 10 and 11. As depicted here, the ram seal 128includes fiber-optic sensors 166 and strain gauges 168 embedded in anelastomeric body 164. In at least one embodiment, and as generally shownin FIG. 11, the strain gauges 168 include single-axis strain gaugesprovided in different orientations so as to function collectively as amulti-axis strain gauge. The ram seal 128 of this embodiment alsoincludes a power supply 170 (e.g., a piezoelectric generator), acommunications antenna 172 (e.g., an RFID antenna), and electronics 174(e.g., data storage 68, processor 70, and communications circuitry).

The ram seals 128 travel with the rams as they close and open the borethrough the blowout preventer. At a minimum they are subject to wellborepressure, friction, and drilling mud. The pressure on the forward faceof the seal is not necessarily always equal to the pressure on the backface of the seal, exacerbating the stresses and strains experienced bythe seal. By embedding sensors in the ram seals, these stresses andstrains can be measured, quantified, and the likely impact on thelongevity of the seals considered from a factual perspective—including,in at least some cases, the temperature of the seal when the forces wereexperienced.

By making measurements such as these, and also the detection of fluidingress, operators can be alerted to potential issues before they becomeproblematic. Through such monitoring, maintenance schedules can becomeproactive rather than reactive. Further, downtime caused by unnecessarymaintenance activities may be reduced, as may downtime caused byunexpected failures.

As with the ram seals 128, the sensors embedded in the ram packers 130(e.g., fiber-optic sensors 148 and strain gauges 154) can be used toacquire various operational data (e.g., temperatures, stresses, andstrains experienced by the ram packers 130) and to optimize maintenancescheduling while minimizing downtime. Unlike the ram seals 128, however,the ram packers 130 are intended to have direct force applied to theirfront faces. This, along with other properties such as deformation,provides additional insights into not just the health of the ram packer130, but also its performance. If a ram is closed and left for a period,the packer material may respond to changes in temperature, to pressurefrom the wellbore material, from other fluids in the blowout preventercavity, and from the natural processes of deformation and relaxationassociated with the material. In such situations it might not be thecase that the changes are sufficient to cause a reduction in sealingefficiency, but by embedding sensors in the packer the data can be madeavailable to the system operator in order that unexpected trends can beidentified and remedial action taken as necessary.

One example of this might be where the ram has been closed and locked,but where there is a leak on the closing side of the piston, in whichcase the holding force of the ram is diminishing over time. Depending onthe instrumentation fitted to the closing mechanism, this reduction inholding pressure might not be detected. A sensor-enabled packer,however, could provide data that would allow the operator to infer thatsomething was wrong somewhere in the closing circuit. If the ram isconfirmed to be locked, then a possible cause of relaxation of themeasured force on the packer could be leakage on the closing side of thepiston. This example illustrates one of the benefits of taking a moreholistic approach to blowout preventer monitoring by allowingmeasurements made for one component to be used in the diagnosis ofproblems in other components.

Another example in which sensor-enabled elastomers could provide usefulinformation is in annular blowout preventers. One example of an annularblowout preventer 180 is generally depicted in FIG. 12. The annularblowout preventer 180 includes a hollow body 182. Drill strings, tools,and other objects may be passed through a bore 184 in the body 182. Asshown, the annular blowout preventer 180 includes a piston 186 and apusher plate 188 that engages a donut 190. Closing pressure forces thepiston 186 and the pusher plate 188 upward, which compresses the donut190 and causes the donut 190 to push the packer 192 radially inward toseal the bore 184. In at least some embodiments, the donut 190 and thepacker 192 have elastomeric bodies. The closed packer 192 can sealaround an object (e.g., a drill string) in the bore 184 or, in at leastsome instances, can seal an open bore.

Sensors can be embedded in any of the sealing components of the annularblowout preventer 180, such as in seals themselves (e.g., the packer192) or in other components that facilitate sealing (e.g., the donut190). As shown in FIG. 12, sensors 202 are embedded in the donut 190 andthe packer 192. The sensors 202 of some embodiments include fiber-opticsensors, but other sensors (e.g., such as strain gauges or sensingwires) could be used in addition to, or in place of such fiber-opticsensors. Although not shown in FIG. 12, it will be appreciated thatother components may also be embedded in the donut 190 and the packer192, such as power supplies, memory devices, processors, andcommunication devices.

By embedding sensors in either or both the donut 190 and the packer 192,the working experience of the annular blowout preventer 180 becomes amatter of record, rather than of speculation. The techniques to beapplied and the benefits derived from such measurements may be similarto those of the ram packer, but whereas the ram packer is asemi-circular, half-torus unit, the annular blowout preventer packer 192and donut 190 are circular. This offers different opportunities for thetypes of sensors to be used and the means of providing power andcommunications to those sensors. The annular packer 192 and donut 190 donot travel in the same way that a ram seal or a ram packer does, sothere is greater scope for wired connections rather than reliance onnon-contact techniques, such as those discussed herein.

An annular blowout preventer is often subject to tool joints of a drillstring (or other objects) being dragged through its packer. For example,an annular packer 192 can be closed about a drill string 198, asgenerally shown in FIG. 13. The donut 190 and the packer 192 aredepicted here as including wired connections 206 and 208 forcommunicating measurements acquired with the sensors 202 for analysis(e.g., by the data analyzer 30). The drill string 198 includes drillpipes coupled together at tool joints 210, and the drill string 198 canbe moved through the annular preventer 180 such that the tool joints 210pass through the closed packer 192. In at least some embodiments, theforces exerted by the joints 210 as they pass can be measured withembedded sensors (e.g., sensors 202) and their likely impact on thehealth and longevity of the packer 192 assessed. In the case of a subseablowout preventer stack, such measurement and assessment may occurbefore the blowout preventer returns to the surface.

Changes in the loading (forces, stresses, strains) on the packer 192 (oron the donut 190) can be used to infer a change in radial dimension ofthe drill string associated with the tool joints 210, allowing detectionof a tool joint 210 as it passes through the packer 192. The axial speedof the drill string 198 could be determined by measuring the elapsedtime between successive tool joint detections in the blowout preventerand calculating speed using the measured time and a known distancebetween the tool joints. In other instances, the speed can be calculatedin different ways. For example, the elapsed time over which theincreased loading associated with a tool joint 210 passing through thepacker 192 is measured by a sensor 202 can be compared with a knownlength of the tool joint 210 to determine the speed of travel. Inanother embodiment, the elapsed time between detection of increasedstress as the tool joint 210 enters the packer 192 (or of decreasedstress as the tool joint 210 exits the packer 192) by separate sensors202 can be used to calculate speed. In one embodiment, an elapsed timesince a tool joint 210 was detected passing through the blowoutpreventer is measured and the location of one or more tool joints 210with respect to the blowout preventer is extrapolated from thecalculated speed and the elapsed time. Knowledge of the distance betweentool joints 210 of the drill string 198 would also allow the position ofadditional tool joints 210 to be determined (e.g., the position of tooljoints above and below the blowout preventer).

Further, in embodiments in which the donut 190 or packer 192 havemultiple sensors 202 provided at different axial locations, a timingdifferential in changes in stress detected by the sensors 202 can beused to detect the direction of travel of the drill string 198. Forinstance, an increase in stress detected first by an upper sensor 202and then by a lower sensor 202 would be indicative of a tool joint 210moving down through the packer 192. Conversely, increased stressdetected first by a lower sensor 202 and then by an upper sensor 202would indicate upward movement of the tool joint 210 through the packer192.

Additionally, in some embodiments changes in loading on smart seals areused to control operation of blowout preventers or other componentshaving the smart seals. For example, changes in loading measured bysensors embedded in a packer of a blowout preventer can be used toadjust closing pressure on the packer. In operation, a closing pressureon the packer 192 of the annular preventer 180 may be sufficient to sealthe packer 192 about the drill string 198 between a pair of tool joints210. Passage of tool joints 210 through the closed packer 192 increasesloading on the packer 192, and the repeated passage of tool joints 210through the packer 192 could negatively impact its health and longevity.While the loading can be measured and used to estimate the long-termeffect of such forces, the detected changes in loading on the packerassociated with the passing tool joints 210 could also or instead beused as feedback for the control of the blowout preventer.

In one embodiment, the closing pressure on the packer is reduced inresponse to a detected increase in the radial dimension of the drillstring, which may be inferred from increased loading measured by anembedded sensor and correspond to entry of a tool joint 210 intoengagement with the packer, as described above. Similarly, the closingpressure on the packer can be increased in response to a detecteddecrease in the radial dimension of the drill string associated with theexit of the tool joint out of engagement with the packer. Thus, forceson the packer can be selectively reduced to facilitate passage of tooljoints and increase longevity of the packer.

In other embodiments, a variable bore ram includes one or more smartseals. A variable bore ram includes a packer that is similar to thoseused in both the pipe ram and annular blowout preventer. That is, it isput into contact with the object (e.g., a drill string) in the blowoutpreventer bore. A secondary mechanism then squeezes the packer in orderto form a tighter seal against the object. By embedding one or moresensors (e.g., fiber-optic sensors or strain gauges) in the variablebore ram packer, it is possible to assess (e.g., from stress and straindata) the actual force applied by the packer to the object. Thisinformation could be used in several ways, including diagnosing problemswith the secondary squeezing mechanism or with the closing system, asdiscussed above.

O-rings (as well as gaskets and other seals) can also be provided assmart seals having embedded sensors. O-rings are used throughout blowoutpreventers and their associated control systems. While it may beimpractical to consider the use of such smart seals in every such case,there may be locations where it is desirable to monitor the health ofO-ring seals. Many of the techniques described previously may applyequally well to O-rings as to the (generally) larger componentsdiscussed above. There will be a limit to how small the various optionalconstituent elements of a smart seal can be, however, and this in turnwill dictate the possible functionality and therefore application ofsmall O-rings. For example, a piezoelectric generator (for local powersupply) or RFID device (for local communications) might be too large tobe embedded in a small O-ring. In such situations, alternatives may beused, such as direct external wired connections for data and power.

As noted above, data acquired with sensors of the smart seals can becommunicated to a processing system (e.g., data analyzer 30) in anysuitable manner, which may include wired or wireless communication ofdata. In some embodiments, a wireless data receiver is positioned withinthe body of an oilfield component so as to be closer to smart sealswithin the oilfield component. In one embodiment depicted in FIG. 15, ablowout preventer 216 includes a ram 218 in a hollow body 220 having abore 222. The blowout preventer 216 also includes a bonnet 224, throughwhich a connecting rod 226 extends. A ram button 228 of the connectingrod 226 is received in the ram 218, allowing movement of the connectingrod 226 through the bonnet 224 to open and close the ram 218 in thepreventer 216. The ram 218 includes a seal 230 (e.g., an elastomericseal) having one or more embedded sensors for acquiring operating datafor the seal. As generally described above, the acquired data mayinclude physical operating data, such as measured forces andtemperatures experienced by the seal 230.

The depicted blowout preventer 216 also includes a data receiver 232 forwirelessly receiving data acquired with and transmitted from the seal230. The data receiver 232 can take any suitable form, but in someinstances is provided as a radio-frequency identification (RFID) readerembedded in the blowout preventer 216 and configured to receive datafrom an RFID tag in the seal 230. The communication range of an RFIDsystem depends on numerous factors, including communication frequency,antenna size, power, surrounding environment, and whether the RFID tagto be read is active or passive. The receiver 232 may be positionedclose to one or more smart seals to be monitored to facilitatecommunication. As shown in FIG. 15, the receiver 232 is embedded withinthe body 220 of the blowout preventer 216 above a ram cavity to providea short communication path between the receiver 232 and the seal 230when the ram 218 is in the open position. Passages 234 in the bonnet 224and the main body of the blowout preventer 220 allow cabling to berouted to the embedded receiver 232. A wired connection 236 facilitatescommunication (e.g., power and data) between the receiver 232 and anexternal system (e.g., data analyzer 30).

In some instances, the communication range of the seal 230 and the RFIDreader or other receiver 232 could be insufficient for reliablecommunication between these components when the ram 218 is moved fromthe open position shown in FIG. 15 to a closed position in the bore 222.In one such embodiment, data acquired by the embedded sensor of the seal230 while the seal is in communication range of the receiver 230 areread in real-time, but the data acquired by the embedded sensor of theseal 230 while the seal 230 is out of communication range from thereceiver 232 (e.g., when the ram 218 is moved away from its openposition) are stored in a memory (e.g., a data storage device 68) withinthe seal 230. The data stored by the smart seal 230 can then be readwith the receiver 232 when reliable communication can be establishedwith the seal 230 (e.g., when the ram 218 moves back to the openposition).

While certain examples of sensors able to measure forces andtemperatures are described above, other sensors with differentcapabilities could be used in smart seals. For example, smart seals ofcertain embodiments include wear indicator sensors that can be used todetect wear or damage to the seals. In one embodiment depicted in FIG.16, a ram packer 244 includes a non-conductive body 246 (e.g., anelastomeric body) between a pair of opposing plates 248. The ram packer244 includes a pipe recess 252, facilitating sealing of the packer 244(more specifically, a front surface 256 of the body 246) about a drillstring or other object in a blowout preventer. A wear sensor 254 isembedded in the body 246 along the front, sealing surface 256. In thepresently depicted embodiment, the wear sensor 254 is provided as anembedded wire extending between opposite ends of the packer 244 alongthe front surface 256, though the wear sensor 254 could take other formsin different embodiments.

The front surface 256 is a wear surface of the packer 244 and graduallyerodes when deployed in a blowout preventer. The wear sensor 254 ispositioned in the body 246 so as to enable detection of a predeterminedamount of wear of the body 246 along the front surface 256. For example,the wear sensor 254 may be provided initially at a predetermined depthbelow the front surface 256. When the material of the body 246 along thefront surface 256 wears by the predetermined amount, the sensor 254 isexposed. The exposed sensor 254 can come into contact with other objects(e.g., a metal drill string in the blowout preventer) to complete anelectrical circuit when a ram carrying the packer 244 is closed. Thiselectrical circuit can be monitored (e.g., by a data analyzer 30) todetect wear of the surface 256 down to the sensor 254, with detectedelectrical contact between the exposed sensor 254 and another objectindicative that the predetermined amount of wear has, in fact, occurred.

The packer 244 is depicted in FIG. 16 with external leads 260electrically coupled to the sensor 254 to facilitate communication witha data analyzer 30 or other external system. An electrical signal can bepassed through the sensor 254 via the leads 260. In one embodiment, thedata analyzer 30 can also test for continuity between the ends of theembedded wire of a sensor 254, with a loss of continuity indicatingdamage to the seal. This detected damage may serve as an earlyindication of impending seal failure. Although not shown in FIG. 16, itwill be appreciated that additional sensors or other components may beembedded in the body 246 of the packer 244. Fiber-optic sensors orstrain gauges, for example, could be embedded in the body 246 to detecttemperatures, forces, and the like. A local power supply (e.g., abattery or piezoelectric generator) and an antenna for wirelesscommunication could also be provided within the body 246. In such cases,the electrical testing could be performed with the local power supplywith results transmitted wirelessly via the antenna, and the wiredexternal leads 260 may be omitted.

Although a ram packer is depicted in FIG. 16, wear sensors like thosedescribed above can be used in other seals as well. For example, a wirecan be provided as a wear sensor in a different ram seal, an annularpacker, a gasket, or an O-ring. By way of example, an elastomer seal 272having a wire wear sensor 274 is depicted in FIGS. 17-19. The seal 272is shown carried by a first component 266 and in sealing contact with asecond component 270 along a surface 268. The first and secondcomponents may move relative to one another, causing wear on the seal272 as it rubs along the surface 268. For instance, in one embodimentthe first component 266 is a piston (e.g., an operating piston of ablowout preventer) and the second component 270 is a housing in whichthe piston reciprocates. In another embodiment, the second component 270could be the moving component (e.g., a rod that moves along the seal 272as the seal is held stationary by the first component 266). In FIG. 17,the wear sensor 274 is electrically isolated from the surface 268 of thecomponent by the body of seal 272. Wear on the seal 272, however, caneventually expose the wear sensor 274 and allow electrical contact withthe surface 268, as generally shown in FIG. 18. In some instances,damage to the sealing surface of the seal 272 can be detected using thewear sensor 274. For example, damage to the sealing surface (e.g., asshown in FIG. 19) can be indicated by a loss of continuity across thewire of the wear sensor 274, as described above.

Although certain examples of sensors and seals monitored with suchsensors are described above, those skilled in the art will appreciatethat the presently disclosed techniques can be used with other sensorsand seals. For example, a wellhead assembly can include other seals withembedded sensors, such as seals in bonnets, connecting rods, flanges,electronics housings (e.g., a subsea electronics module housing), andcomponents of a blowout preventer control system. Seals with conditionsensors may also be used in other subsea or surface oilfield components(whether as part of or separate from a wellhead assembly), such aspumps, separators, generators, motors, gearboxes, processing equipment,production equipment, chokes, and valves. Further still, it will beappreciated that the present techniques discussed herein also haveapplication in other industries that may benefit from monitoring thehealth and operating experience of seals and gaskets.

While the aspects of the present disclosure may be susceptible tovarious modifications and alternative forms, specific embodiments havebeen shown by way of example in the drawings and have been described indetail herein. But it should be understood that the invention is notintended to be limited to the particular forms disclosed. Rather, theinvention is to cover all modifications, equivalents, and alternativesfalling within the spirit and scope of the invention as defined by thefollowing appended claims.

1. A method comprising: closing a blowout preventer about a drillstring, the blowout preventer including a sealing component having anelastomeric body with an embedded sensor; and detecting a tool joint ofthe drill string as the drill string is moved axially through the closedblowout preventer, wherein detecting the tool joint includes detecting achange in a radial dimension of the drill string using the embeddedsensor.
 2. The method of claim 1, wherein detecting the change in theradial dimension of the drill string using the embedded sensor includesdetecting a change in loading on the sealing component resulting frommovement of the tool joint within the closed blowout preventer via theembedded sensor and inferring passage of the tool joint through theclosed blowout preventer from the change in loading on the sealingcomponent.
 3. The method of claim 1, comprising determining the locationof the tool joint or of an additional tool joint of the drill stringwith respect to the closed blowout preventer after the tool joint hasexited the closed blowout preventer based on data from the embeddedsensor.
 4. The method of claim 3, wherein determining the location ofthe tool joint or of the additional tool joint with respect to theclosed blowout preventer after the tool joint has exited the closedblowout preventer based on data from the embedded sensor includes:detecting increased loading on a packer of the closed blowout preventerresulting from passage of the tool joint through the packer of theclosed blowout preventer; measuring an elapsed time of the increasedloading on the packer resulting from passage of the tool joint throughthe packer; and extrapolating the position of the tool joint or of theadditional tool joint based on the elapsed time.
 5. The method of claim3, wherein determining the location of the tool joint or of theadditional tool joint with respect to the closed blowout preventer afterthe tool joint has exited the closed blowout preventer based on datafrom the embedded sensor includes: detecting increased loading on apacker of the closed blowout preventer resulting from passage ofmultiple tool joints through the packer of the closed blowout preventer;measuring an elapsed time between passage of at least two of themultiple tool joints through the packer; and extrapolating the positionof the tool joint or of the additional tool joint based on the elapsedtime.
 6. The method of claim 1, comprising reducing closing pressure onthe sealing component in response to detecting, with the embeddedsensor, an increase in the radial dimension of the drill stringcorresponding to entry of the tool joint into engagement with a packerof the closed blowout preventer.
 7. The method of claim 6, comprisingincreasing closing pressure on the sealing component in response todetecting, with the embedded sensor, a decrease in the radial dimensionof the drill string corresponding to exit of the tool joint out ofengagement with the packer of the closed blowout preventer.
 8. Themethod of claim 1, wherein the sealing component having the elastomericbody with the embedded sensor is a packer that is in contact with thedrill string.
 9. The method of claim 1, wherein the blowout preventerincludes a packer that is in contact with the drill string, and thesealing component having the elastomeric body with the embedded sensoris a biasing component that biases the packer to increase sealingpressure of the packer against the drill string.
 10. The method of claim9, wherein closing the blowout preventer about the drill string includescompressing the biasing component such that the biasing component pushesthe packer radially inward against the drill string.
 11. A methodcomprising: reading seal operational data for a seal of an oilfieldcomponent acquired with a sensor embedded in the seal of the oilfieldcomponent; comparing the seal operational data for the seal of theoilfield component to baseline data for similar seals; and calculatingan expected performance characteristic of the seal of the oilfieldcomponent based on the comparison of the seal operational data to thebaseline data.
 12. The method of claim 11, wherein reading sealoperational data includes reading stress measured by the sensor embeddedin the seal of the oilfield component, comparing seal operational datato baseline data for similar seals includes comparing the stressmeasured by the sensor to baseline stress data for the similar seals,and calculating the expected performance characteristic of the seal ofthe oilfield component includes calculating expected longevity of theseal based on the comparison of the stress measured by the sensor to thebaseline stress data.
 13. The method of claim 12, wherein the sealoperational data also includes temperature data for the seal of theoilfield component, the baseline data for similar seals includesbaseline temperature data for the similar seals, comparing sealoperational data to baseline data for similar seals includes comparingthe stress and temperature data for the seal of the oilfield componentto baseline stress and temperature data for the similar seals, andcalculating the expected performance characteristic of the seal of theoilfield component includes calculating expected longevity of the sealof the oilfield component based on the comparison of the measured stressand temperature data for the seal of the oilfield component to thebaseline stress data.
 14. The method of claim 11, wherein the seal ofthe oilfield component includes a seal that contacts an additional partof the oilfield component, the seal and the additional part undergorelative motion, and reading seal operational data includes readingstress measured during the relative motion by the sensor embedded in theseal.
 15. The method of claim 14, comprising: determining an amount offriction on the seal due to the relative motion; comparing the amount offriction on the seal to a friction threshold; and alerting an operatorthat the amount of friction on the seal has exceeded the frictionthreshold.
 16. The method of claim 11, comprising acquiring the sealoperational data with the sensor embedded in the seal of the oilfieldcomponent.
 17. An apparatus comprising: an oilfield component including:a hollow body having a bore; a seal that can be selectively closed toseal against an object in the bore of the hollow body; and a sensor formeasuring operational data of the seal.
 18. The apparatus of claim 17,comprising a controller operable to control a closing pressure on theseal of the oilfield component based on the operational data of the sealmeasured by the sensor of the oilfield component.
 19. The apparatus ofclaim 18, wherein the controller is operable to detect a tool joint ofthe object in contact with the seal of the oilfield component.
 20. Theapparatus of claim 17, wherein the oilfield component is a blowoutpreventer.